Abstract

Standard methods to predict pore pressure rely on the assumption that under-compaction is the only mechanism for overpressure generation. For conventional plays, this assumption may be held since the weight of the overlying sediments is supported partly by the rock matrix and partly by the confined interstitial fluids, resulting in an overpressured formation. In a Tight Gas Sand reservoir, it becomes necessary to check the methodologies to predict pore pressure, since the source of overpressure is not clear and the absence of a thick mudrock layer does not allow to find trends of preserved porosity in fine layers. This paper shows a workflow to generate a pore pressure model at reservoir scale in a Tight Gas Sand reservoir. Sonic logs, density logs and DFIT data of around 50 wells were used to correlate the porosity with the vertical effective stress (VES), which is the difference between the overburden and the pore pressure.

1. INTRODUCTION

In the last five years, unconventional reservoirs in Argentina, particularly in the Neuquen Basin, have been intensively developed, mainly for the needs to have new sources of hydrocarbons to supplement the production of the already exploited conventional reservoirs.

The difficulties encountered to develop these plays, justify the need to get new and more accurate reservoir data, to revise the methods traditionally used, and to analyze reservoirs from a different perspective. For example, the mechanical behavior of reservoirs started to play a key role in their development, especially at the drilling and stimulation stages.

Among the geomechanical variables that play a fundamental role in the reservoir development, an accurate pore pressure prediction is fundamental to execute a safe drilling strategy, to accurately perform a production forecast and modelling, and also to establish the stress state, which sets the behavior of the hydraulic fracture.

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